In a conventional drilling system for drilling an earthen formation, the drilling system includes a drilling rig used to turn a drilling tool assembly that extends downward into a wellbore. The drilling tool assembly includes a drill string and a bottom hole assembly (BHA). The drill string includes several joints of drill pipe connected end to end through tool joints. The drill string is used to transmit drilling fluid (through its hollow core) and to transmit rotational power from the drill rig to the BHA. A wide variety of bottom hole assemblies have previously been used to form wellbores in downhole formations. Typically, the bottom hole assembly contains at least a drill bit. Typical BHA's may also include additional components attached between the drill string and the drill bit. Examples of additional BHA components include, but are not limited to, drill collars, stabilizers, measurement-while-drilling (MWD) tools, logging-while-drilling (LWD) tools, subs, hole enlargement devices (e.g., hole openers and reamers), jars, accelerators, thrusters, downhole motors, and rotary steerable systems.
Drilling a borehole for the recovery of hydrocarbons or minerals is typically very expensive due to the high cost of the equipment and personnel that are required to safely and effectively drill to the desired depth and location. The total drilling cost is proportional to the length of time it takes to drill the borehole. The drilling time, in turn, is greatly affected by the rate of penetration (ROP) of the drill bit and the number of times the drill bit must be changed in the course of drilling. A bit may need to be changed because of wear or breakage. Each time the bit is changed, the entire drill string and BHA, which may be may be miles long, must be retrieved from the borehole, section by section. Once the drill string has been retrieved and the new bit installed, the bit must be lowered to the bottom of the borehole on the drill string which must be reconstructed again, section by section. As is thus obvious, this process, known as a “trip” of the drill string, requires considerable time, effort, and expense. Accordingly, because drilling cost is time dependent, it is desirable to employ drill bits that will drill faster and longer and that are useable over a wide range of differing formation hardnesses.
The length of time that a drill bit may be employed before the drill string must be tripped and the bit changed depends upon the bit's rate of penetration (ROP), as well as its durability, that is, its ability to maintain a high or acceptable ROP. Additionally, a desirable characteristic of the bit is that it is stable and resists vibration, the most severe type or mode of which is “whirl.” Whirl is a term used to describe the phenomenon where a drill bit rotates at the bottom of the borehole about a rotational axis that is offset from the geometric center of the drill bit. The whirling subjects the cutter elements on the bit to increased load, impact and wear, which can cause premature failure of the cutter elements and a loss of penetration rate. Other forms of vibrational forces include axial, lateral and torsional forces exerted on the drill bit.
A typical drill bit used in a BHA is a fixed cutter rotary drill bit, also referred to as a “drag” bit. Referring to FIG. 1, a fixed cutter rotary drill bit is shown. The drill bit 10 includes a steel bit body 12 (or a matrix bit body), which includes at least one cutter element 40, 50, a shank 13, and a threaded connection or pin 14 for connecting bit 10 to a drill string (not shown). A cutting structure 15 is provided on the bit face 20 of bit 10. Cutting structure 15 includes three angularly spaced-apart primary blades 31, 32, 37 and three secondary blades 33, 34, 35, which extends generally outwardly away from a central longitudinal axis 11 of the drill bit 10. The cutter elements 40, 50 are disposed on the primary blades 31, 32, 37 and secondary blades 33, 34, 35. The blades include cutter pockets 23 which are adapted to receive the cutter elements 40, 50, and the cutter elements 40, 50 are usually brazed into the cutter pockets 23. The blades include gage pads 51 which contact the wall of the bore hole (not shown). The number of blades and/or cutter elements is related, among other factors, to the type of formation to be drilled, and can thus be varied to meet particular drilling requirements.
Another drill bit used in a BHA is a hybrid rotary drill bit, as shown in FIG. 2, which is a diamond impregnated bit 10 with one or more cutter elements 40 placed within a cutter pocket 23 on the one or more diamond impregnated blades 195 or “ribs”.
Another drill bit used in a BHA is a bi-centered drill bit, as shown in FIG. 3. A conventional bi-center bit 71 comprises a lower pilot bit section 10 and a longitudinally offset, radially extending reaming section 72. During drilling, the bit rotates about the central axis 11 of the pilot section, causing the reaming section 72 to cut a hole having a diameter equal to twice the greatest radius of the reaming section 72. Cutter elements 40 are located on the bit 10 and cutter elements 70 are located on the reaming section 72.
It is desirable to design a bottom hole assembly comprising a drill bit which optimizes the arrangement of cutting elements to enhance drilling performance and extend the drilling life of the drill bit and BHA.